Bi-Axial Drill Bits and Bit Adaptors

ABSTRACT

Drill bits comprise a body having an uphole end and a downhole end. The uphole end is adapted for connection to a tool assembly for rotating the drill bit. The tool assembly has an axis of rotation. The downhole end has one or more cutting members adapted for removing material in contact with the downhole end when the drill bit is rotated. The body has an uphole major axis and a downhole major axis. The uphole axis and the downhole axis are offset from each other. The uphole axis is central to the uphole end and is aligned with the tool assembly axis of rotation. The uphole axis defines an axis of rotation for the drill bit. The downhole axis is central to the downhole end.

FIELD OF THE INVENTION

The present invention relates generally to drill bits used to drill out frac plugs in oil and gas wells and to adaptors for such bits. More particularly, it relates to drill bits which are adapted to have an extended sweep around the interior of a liner and to adaptors for conventional drill bits which are adapted to provide the bit with an extended sweep.

BACKGROUND OF THE INVENTION

Hydrocarbons, such as oil and gas, may be recovered from various types of subsurface geological formations. The formations typically consist of a porous layer, such as limestone and sands, overlaid by a nonporous layer. Hydrocarbons cannot rise through the nonporous layer. Thus, the porous layer forms a reservoir, that is, a volume in which hydrocarbons accumulate. A well is drilled through the earth until the hydrocarbon bearing formation is reached. Hydrocarbons then are able to flow from the porous formation into the well.

In what is perhaps the most basic form of rotary drilling methods, a drill bit is attached to a series of pipe sections referred to as a drill string. The drill string is suspended from a derrick and rotated by a motor in the derrick. A drilling fluid or “mud” is pumped down the drill string, through the bit, and into the well bore. This fluid serves to lubricate the bit and carry cuttings from the drilling process back to the surface. As the drilling progresses downward, the drill string is extended by adding more pipe sections.

When the drill bit has reached the desired depth, larger diameter pipes, or casings, are placed in the well and cemented in place to prevent the sides of the borehole from caving in, Cement is introduced through a work string. As it flows out the bottom of the work string, fluids already in the well, so-called “returns,” are displaced up the annulus between the casing and the borehole and are collected at the surface.

Once the casing is cemented in place, it is perforated at the level of the oil bearing formation to create openings through which oil can enter the cased well. Production tubing, valves, and other equipment are installed in the well so that the hydrocarbons may flow in a controlled manner from the formation, into the cased well bore, and through the production tubing up to the surface for storage or transport.

This simplified drilling and completion process, however, is rarely possible in the real world. Hydrocarbon bearing formations may be quite deep or otherwise difficult to access. Thus, many wells today are drilled in stages. An initial section is drilled, cased, and cemented. Drilling then proceeds with a somewhat smaller well bore which is lined with somewhat smaller casings or “liners.” The liner is suspended from the original or “host” casing by an anchor or “hanger.” A seal also is typically established between the liner and the casing and, like the original casing, the liner is cemented in the well. That process then may be repeated to further extend the well and install additional liners. In essence, then, a modern oil well typically includes a number of tubes telescoped wholly or partially within other tubes.

Moreover, hydrocarbons are not always able to flow easily from a formation to a well. Some subsurface formations, such as sandstone, are very porous. Hydrocarbons are able to flow easily from the formation into a well. Other formations, however, such as shale rock, limestone, and coal beds, are only minimally porous. The formation may contain large quantities of hydrocarbons, but production through a conventional well may not be commercially practical because hydrocarbons flow though the formation and collect in the well at very low rates. The industry, therefore, relies on various techniques for improving the well and stimulating production from formations. In particular, various techniques are available for increasing production from formations which are relatively nonporous.

Perhaps the most important stimulation technique is the combination of horizontal well bores and hydraulic fracturing. A well will be drilled vertically until it approaches a formation. It then will be diverted, and drilled in a more or less horizontal direction, so that the borehole extends along the formation instead of passing through it. More of the formation is exposed to the borehole, and the average distance hydrocarbons must flow to reach the well is decreased. Fractures then are created in the formation which will allow hydrocarbons to flow more easily from the formation.

Fracturing a formation is accomplished by pumping fluid, most commonly water, into the well at high pressure and flow rates. The fluid is injected into the formation, fracturing it and creating flow paths to the well. Proppants, such as grains of sand, ceramic or other particulates, usually are added to the frac fluid and are carried into the fractures. The proppant serves to prevent fractures from closing when pumping is stopped.

Fracturing typically involves installing a production liner in the portion of the well bore which passes through the hydrocarbon bearing formation. The production liner commonly incorporates an “initiator” or “toe” valve at the end which can be actuated to open ports in the valve. The liner also may incorporate a series of frac valves, typically ball-drop, sliding sleeve valves, which are arrayed along the length of the liner. The frac valves will be actuated by pumping a ball or other plug into the valve. The ball will actuate the sleeve to open ports in the valve. The ball restricts flow through the valve and diverts it through the ports and into the formation. Once fracturing is complete various operations will be performed to “unplug” the valve and allow fluids from the formation to enter the liner and travel to the surface.

In many wells, however, the production liner does not incorporate frac valves. Instead, fracturing will be accomplished by “plugging and perfing” the liner. In a “plug and pert” job, the production liner is made up from standard lengths of liner. The liner usually will incorporate a toe valve near its end, but otherwise does not have any openings through its sidewalls, nor does it incorporate frac valves. It is installed in the well bore, and holes then are punched in the liner walls. The perforations typically are created by so-called “perf” guns which discharge shaped charges through the liner and, if present, adjacent cement.

A well almost always will be fractured at many different locations, but rarely, if ever, will the well be fractured all at once. The toe valve will be opened, usually by increasing hydraulic fluid in the liner. Fluids then are pumped into the well to fracture the formation in the vicinity of the toe valve.

After the initial zone is fractured, a plug is installed in the liner at a point above the toe valve and the first fractured zone. The liner is perforated, typically at several locations above the plug. A ball then is deployed onto the plug. The ball will restrict fluids from flowing through and past the plug. When fluids are injected into the liner, therefore, they will be forced to flow out the perforations and into a second zone. After the second zone is fractured, additional plugs are installed, and the process is repeated until all zones in the well are fractured.

After the well has been fractured, however, plugs may interfere with installation of production equipment in the liner, or they may restrict the flow of production fluids upward through the liner. Thus, plugs typically are removed from the liner after the well has been fractured. Retrievable plugs are designed to be set and then unset. Once unset, they may be removed from the well. Non-retrievable plugs are designed to be more or less permanently installed in the liner. Once installed, they must be drilled out to open up the liner.

At first glance, a “drill-out” of non-retrievable plugs is a relatively simple operation. A drill-out tool assembly is run into the production liner. Most commonly, the tool assembly will be run into the liner on coiled tubing and will include a downhole motor and a bit. The motor will drive the bit, rotating it, to gradually remove material from the plug and eventually open up the liner. Some or all of the components of many conventional non-retrievable frac plugs also are fabricated from more easily drillable materials. Composite materials in particular are more easily drilled and, therefore, can make it easier to drill out a plug. They also can allow for less aggressive drilling and reduce the likelihood and amount of resulting damage to a liner.

A plug, however, necessarily must seal against the entire inner circumference of the liner or it will leak. At the same time, a drill bit must have a diameter somewhat smaller than the liner into which it will be deployed. Otherwise, it will not be able to travel easily through the liner. It may get stuck on the way down. The sweep of the drill bit as it is rotated, therefore, necessarily will be less than the full diameter of the plug. Relatively large pieces of a plug may be left intact after the bit has traveled through the plug.

The debris created by drilling out non-retrievable plugs must be circulated out of the well so it does not interfere with production equipment that will be installed in the liner. Large pieces of debris are more difficult to circulate out of the liner. They also are more likely to create issues with equipment in the well. Additionally, even plugs which are fabricated primarily from more easily drillable composites may still incorporate metal components. Metal components, especially annular metal components, can exacerbate problems in running a bit with a sweep smaller than the internal diameter of the liner.

The statements in this section are intended to provide background information related to the invention disclosed and claimed herein. Such information may or may not constitute prior art. It will be appreciated from the foregoing, however, that there remains a need for new and improved composite plugs and for new and improved methods for fracking or otherwise stimulating formations using composite plugs. Such disadvantages and others inherent in the prior art are addressed by various aspects and embodiments of the subject invention.

SUMMARY OF THE INVENTION

The subject invention relates generally to drill bits with an extended sweep and to adaptors for standard drill bits which provide a standard drill bit with an extended sweep. It encompasses various embodiments and aspects, some of which are specifically described and illustrated herein. In one embodiment, the novel drill bits comprise a body having an uphole end and a downhole end. The uphole end is adapted for connection to a tool assembly for rotating the drill bit. The tool assembly has an axis of rotation. The downhole end has one or more cutting members adapted for removing material in contact with the downhole end when the drill bit is rotated. The body has an uphole major axis and a downhole major axis. The uphole axis and the downhole axis are offset from each other. The uphole axis is central to the uphole end and is aligned with the tool assembly axis of rotation. The uphole axis defines an axis of rotation for the drill bit. The downhole axis is central to the downhole end.

Other embodiments provide such drill bits where the uphole axis and the downhole axis are generally parallel to each other. Still other embodiments provide such drill bits where the drill bit is a rotary cone, fixed head, or other conventional type of drill or mill bit.

In other aspects and embodiments, the subject invention provides for novel adaptors for a drill bit. The adaptor comprises a body having an uphole end and a downhole end. The uphole end is adapted for connection to a tool assembly for rotating a drill bit. The tool assembly has an axis of rotation. The downhole end is adapted for connection to a drill bit. The drill bit has an axis of rotation. The body has an uphole major axis and a downhole major axis. The uphole axis is adapted for alignment with the tool assembly axis of rotation. The downhole axis is adapted for alignment with the drill bit axis of rotation. The uphole axis and the downhole axis are offset from each other.

Other embodiments provide such adaptors where the uphole axis and the downhole axis are generally parallel to each other.

Additional embodiments provide such adaptors where the body defines a central passage extending laterally through the body. Other embodiments provide such adaptors where the body defines a circulation port extending from the central passage to the exterior of the body. The port is adapted to conduct fluid from the central passage to the exterior of the adaptor. In still other embodiments, the circulation port is directed generally downhole or is directed generally uphole.

In yet other aspects, the invention provides for a drilling tool assembly which comprises a drill bit and a novel adaptor.

The invention also provides methods for performing an operation to drill out obstructions in a well tubular. The method comprises running a tool assembly into the tubular. The tool assembly has an axis of rotation and comprises a drill bit having one or more cutting members at its downhole end. The cutting members are adapted for removing material from the obstruction. The downhole end of the tool bit has a central axis offset from the tool assembly axis of rotation. Once the tool assembly is run into the tubular, the tool assembly is rotated to cause the drill bit to drill out the obstruction.

Other embodiments provide such methods where the tool assembly comprises an adaptor. The adaptor has a first axis aligned with the tool assembly axis of rotation and a second axis aligned with the tool bit central axis.

Still other embodiments provide such methods which include circulating fluid through a central passage extending laterally through the adaptor and a port extending from the central passage to the exterior of the adaptor.

In yet other aspects and embodiments, the invention provides such methods where the drill bit is a rotary cone, fixed head, or other conventional type of drill or mill bit.

Finally, still other aspect and embodiments of the novel apparatus and methods will have various combinations of such features as will be apparent to workers in the art.

Thus, the present invention in its various aspects and embodiments comprises a combination of features and characteristics that are directed to overcoming various shortcomings of the prior art. The various features and characteristics described above, as well as other features and characteristics, will be readily apparent to those skilled in the art upon reading the following detailed description of the preferred embodiments and by reference to the appended drawings.

Since the description and drawings that follow are directed to particular embodiments, however, they shall not be understood as limiting the scope of the invention. They are included to provide a better understanding of the invention and the manner in which it may be practiced. The subject invention encompasses other embodiments consistent with the claims set forth herein.

BRIEF DESCRIPTION OF THE DRAWINGS

FIG. 1A (prior art) is a schematic illustration of an early stage of a “plug and perf” fracturing operation showing a tool string 11 deployed into a liner assembly 4, where tool string 11 includes a perf gun 13, a setting tool 14, and a plug 20 a.

FIG. 1B (prior art) is a schematic illustration of liner assembly 4 after completion of the plug and perf fracturing operation, but before removal of plugs 20 from liner 4.

FIG. 2 (prior art) is an elevational view (with partial cross-section) of a drill bit 30 approaching plug 20 (shown in cross-section) which has been installed in a liner 4.

FIG. 3 is a diagram showing the sweep S_(B) of conventional bit 30 shown in FIG. 1 as compared to the inner circumference C_(L) of liner 4.

FIG. 4 is an elevational view (with partial cross-section) of drill bit 30 assembled to a first preferred embodiment 40 of the novel bit adaptors (shown in cross-section).

FIG. 5 is an elevational view (with partial cross-section) of drill bit 30 assembled to a second preferred embodiment 140 of the novel bit adaptors (shown in cross-section).

FIG. 6 is an elevational view (with partial cross-section) of drill bit 30 assembled to a third preferred embodiment 240 of the novel bit adaptors (shown in cross-section).

FIG. 7 is a cross-sectional view of a fourth preferred embodiment 340 of the novel bit adaptors which may be assembled to drill bit 30.

FIG. 8 is an isometric view of adaptor 340.

FIG. 9 is an end view of adaptor 340.

FIG. 10 is a partial elevational, partial cross-sectional view of a first preferred embodiment 130 of the novel drill bits of the subject invention approaching plug 20 (shown in cross-section).

In the drawings and description that follows, like parts are identified by the same reference numerals. The drawing figures are not necessarily to scale. Certain features of the embodiments may be shown exaggerated in scale or in somewhat schematic form and some details of conventional design and construction may not be shown in the interest of clarity and conciseness.

DESCRIPTION OF ILLUSTRATIVE EMBODIMENTS

The present invention generally relates to drill bits which are adapted to have an extended sweep around the interior of a liner and to adaptors for conventional drill bits which are adapted to provide the bit with an extended sweep. For the sake of conciseness, all features of an actual implementation may not be described or illustrated. In developing any actual implementation, as in any engineering or design project, numerous implementation-specific decisions must be made to achieve a developers' specific goals. Decisions usually will be made consistent within system-related and business-related constraints, and specific goals may vary from one implementation to another Development efforts might be complex and time consuming and may involve many aspects of design, fabrication, and manufacture. Nevertheless, it should be appreciated that such development projects would be a routine effort for those of ordinary skill having the benefit of this disclosure.

Overview of Plug and Perf Fracturing Operations

As may be seen in the schematic representations of FIG. 1, plugs 20 may be used to perform a “plug and perf” fracturing operation in an oil and gas well 1. Plugs 20 are described to a certain extent below, but are more fully described in applicant's U.S. patent application Ser. No. 15/414,378, filed Jan. 24, 2017, the disclosure of which is incorporated herein by reference. It will be noted that plug 20 is substantially identical to plug 216 disclosed in the '378 application.

Well 1 is serviced by a well head 2 and various other surface equipment (not shown). Well head 2 and the other surface equipment will allow frac fluids to be introduced into the well at high pressures and flow rates. The upper portion of well 1 is provided with a casing 3 which extends to the surface. A production liner 4 has been installed in the lower portion of casing 3 via a liner hanger 5. It will be noted that the lower part of well 1 and liner 4 extend generally horizontally through a hydrocarbon bearing formation 6. Liner 4, as installed in well 1, is not provided with valves or any openings in the walls thereof other than a toe valve 10. Liner 4 also has been cemented in place. That is, cement 7 has been introduced into the annular space between liner 4 and the well bore 8.

A typical frac job will proceed in stages from the lowermost zone in a well to the uppermost zone. Thus, FIG. 1A shows well 1 after the initial stage of a frac job has been completed. Toe valve 10 was closed when liner 4 was run in and installed, but it now has been opened. Fluid has been introduced into formation 6 via ports in open toe valve 10, and fractures 9 extending from toe valve 20 have been created in a first zone near the bottom of well 1.

A tool string 11 has been run into liner 4 on a wireline 12. Tool string 11 comprises a perf gun 13, setting tool assembly 14 (which may include an adapter kit), and frac plug 20 a. Tool string 10 is positioned in liner 4 such that frac plug 20 a is uphole from toe valve 10. Frac plug 20 a is coupled to setting tool 14 and will be installed in liner 4 by actuating setting tool 14 via wireline 12. Once plug 20 a has been installed, setting tool 14 will be released from plug 20 a. Perf gun 13 then will be fired to create perforations 15 a in liner 4 uphole from plug 20 a. Perf gun 13 and setting tool 14 then will be pulled out of well 1 by wireline 12.

A frac ball (not shown) then will be deployed onto plug 20 a to restrict the downward flow of fluids through plug 20 a, Plug 20 a, therefore, will substantially isolate the lower portion of well 1 and the first fractures 9 extending from toe valve 10. Fluid then can be pumped into liner 4 and forced out through perforations 15 a to create fractures 9 in a second zone. After fractures 9 have been sufficiently developed, pumping is stopped and valves in well head 2 will be closed to shut in well 1. After a period of time, fluid will be allowed to flow out of fractures 9, through liner 4 and casing 3, to the surface. Additional plugs 20 b to 20 z then will be run into well 1 and set, liner 4 will be perforated at perforations 15 b to 15 z, and well 1 will be fractured in succession as described above until, as shown in FIG. 1B, all stages of the frac job have been completed and fractures 9 have been established in all zones.

It will be noted that FIG. 1 are greatly simplified schematic representations of a plug and perf fracturing operation. Production liner 4 is shown only in part as such liners may extend for a substantial distance. The portion of liner 4 not shown also will be provided with perforations 15 and plugs 20, and fractures 9 will be established in the formation 6 adjacent thereto. In addition, FIG. 1 depict only a few perforations 15 in each zone, whereas typically a zone will be provided with many perforations. Likewise, a well may be fractured in any number of zones, thus liner 4 may be provided with more or fewer plugs 20 than depicted.

The terms “upper” and “lower” and “uphole” and “downhole” as used herein to describe location or orientation are relative to the well and to the tool as run into and installed in the well. Thus, “upper” and “uphole” refers to a location or orientation toward the upper or surface end of the welt. “Lower” or “downhole” is relative to the lower end or bottom of the well. It also will be appreciated that the course of the well bore may not necessarily be as depicted schematically in FIG. 1. Depending on the location and orientation of the hydrocarbon bearing formation to be accessed, the course of the well bore may be more or less deviated in any number of ways. “Axial,” “radial,” and forms thereof reference the central axis of the tools. For example, axial movement or position refers to movement or position generally along or parallel to the central axis. “Lateral” movement and the like also generally refers to up and down movement or positions up and down the tool, “Radial” will refer to positions or movement toward or away from the central axis.

Overview of Drill-Out Operations

Some operators may prefer to produce hydrocarbons from well 1 without removing plugs 20 from liner 4. In such instances, dissolvable frac balls will be used in the fracturing operation. Dissolvable balls, as their name implies, are fabricated from a material that dissolves, softens, or disintegrates in the presence of well fluids after a period of time (typically 1 to 30 days) such that the balls do not thereafter interfere with the upward flow of fluids through plugs 20.

More commonly, however, operators will prefer to remove plugs 20 from liner 4, even if dissolvable frac balls are employed. Frac plugs 20 may interfere with the installation of production equipment in liner 4 and, depending on production rates, may restrict the upward flow of production fluids through liner 4. Thus, for example, a tool assembly including a motor and a drill bit may be deployed into liner 4 on coiled tubing. Mill bits also may be used but generally are less preferable. In either event, plugs 20 will be drilled out in succession from top to bottom. Debris from plugs 20 preferably is circulated out of liner 4 during the drilling process.

Frac plug 20 is shown in FIG. 2 after it has been set in liner 4. As shown therein, frac plug 20 generally comprises an annular wedge 21, a sealing ring 22, and an annular slip 23. Annular slip 23 is composed of a plurality of individual slip segments. Collet fingers 24 extend downward from the lower end of wedge 21. A gauge ring 25 is secured to the lower ends of collet fingers 24. A setting ring 26 together with setting tool 14 has been used to install plug 20 in liner 4, and a frac ball 27 has been deployed into plug 20, all as described in detail in the '387 application.

A conventional drill bit 30 is shown in FIG. 2, and in FIGS. 4-6 discussed below. As shown in FIG. 2, bit 30 has been run into liner 4 until it is proximate to the top of plug 20. Drill bit 30 will be rotated to mill away plug 20. The operation of the tool assembly will be controlled largely with the particular plug and bit in mind. Typically, however, the bit will be rotated at about 200-300 rpm. The weight on the bit (WOB) typically will be up to about 4,000 pounds. Faster drilling (higher rpms and WOB) generally will produce larger cuttings. Slower drilling (lower rpms and WOB) generally will produce smaller cuttings.

Most commonly, drill bit 30 will be driven by a downhole motor, such as a Moineau motor, which is run into the well on coiled tubing. Moineau motors, also known as progressive cavity motors, are powered by pumping fluid through coiled tubing and into the motor. Fluid passing through the motor causes a rotor to rotate within the motor housing, and that rotation is transmitted via a draft shaft to the bit. Joints, such as universal joints, may be used to allow the drill-out tool assembly to bend yet still transmit rotation. The drill-out tool assembly also may include circulation tools and valves. Such tools may be used to divert circulation from the motor as the tool assembly is run into the liner, thereby minimizing rotation and reducing wear in the motor. The tool assembly also may simply be a work string which is rotated at the surface. Such motors and tools, and other tools used in drill-out tool assemblies are well known in the art and, for the sake of clarity, have been omitted from FIGS. 2 and 4-6.

Drill bit 30 is a conventional roller cone (aka rotary cone) drill bit. It perhaps may be best appreciated by viewing FIGS. 5-6, which show bit 30 generally from an elevational view, but with the uphole end shown in cross-section. As may be seen therein, drill bit 30 generally comprises a bit body 31 and three cone assemblies 32. Drill bit 30 is adapted for connection to a motor or other component of a tool assembly (not shown). Thus, the upper end of bit body 31 terminates in a threaded pin 33. Pin 33 allows bit 30 to be threaded, for example, into the drive shaft of a downhole motor.

Cones 32 are mounted for rotation on spindles (not shown). The spindles extend radially inward and downward from the lower end of three support legs 34 on bit body 31 along what is commonly referred to as the cone rotational axis. Cones 32 will be subject to high stress during drilling operations. Thus, they are mounted on the spindle by a sealed bearing assembly (not shown). The bearing assembly may include various combinations of bearings, such as sleeve bearings, pin bearings, ball bearings, and thrust bearings. Typically, the bearing assembly will be fed grease through a grease reservoir (not shown). Cones 32, as their name implies, are generally cone-shaped bodies on which various cutting members, such as compacts, inserts, and milled teeth, are provided. The cutting members will enable drill bit 30 to crush, penetrate, scrape or shear away plug 20. For example, cones 32 are provided with a plurality of inserts 35. Inserts 35 are arranged in three rows extending circumferentially around the exterior surface of cones 32. The first row, which runs around the base of the cone, is typically referred to as a gauge row. The inserts are formed in part or in whole of extremely hard materials. Suitable materials include metal alloys and cermets, such as tungsten carbides (e.g., monotungsten carbide, ditungsten carbide, microcrystalline tungsten carbide, and cemented or sintered tungsten carbide), as well as other metal carbides, metal borides, metal oxides, and metal nitrides. Polycrystalline diamond (PCD) type materials also may be used. The cone rotational axis, as well as the number, type, geometry, and arrangement of cutting members will be varied as known in the art to provide the desired milling characteristics.

The bottom or “backface” of cones 32 and the exterior surface of legs 34 also may be provided with compacts or inserts to provide gage stabilization. Areas particularly susceptible to wear, such as the bottom or “shirttails” of legs 34, may have hard metal welded onto them for additional protection. Bit body 31 also is provided with a central conduit 36 allowing fluids to be introduced into drill bit 30 through a motor assembly or other work string. Ports (not shown) extend from central conduit 36 through bit body 31, terminating in nozzles 37 which direct fluid out of bit 30 as it is rotated. The circulating fluid will assist in carrying cuttings away from drill bit 30 as it mills away plug 20.

It will be appreciated that bit body 31, pin 33, cones 32, and other components of drill bit 30 are arranged substantially symmetrically about a central axis A_(B) extending from the upper to the lower end of drill bit 30. When mounted, drill bit 30 will be in substantial alignment with the tool assembly. That is, axis A_(B) is substantially collinear with the rotational axis of the tool assembly. Axis A_(B) thus provides an axis of rotation for drill bit 30, and excepting vibration along the drill-out tool assembly, the sweep of drill bit 30 will be essentially circular.

While the figures are not limited to a particular orientation, the orientation of FIG. 2 is useful for understanding the issues that may be encountered in a drill-out operation if a plug is installed in a horizontal extension of well 1. Liner 4, for example, may have a nominal inner diameter of 4.778″. Drill bit 30 will have a smaller sweep, for example, a sweep of 4.625″ in diameter, some 0.152″ less than the inner diameter of liner 4. Thus, is drill bit 30 will tend to ride on the bottom of liner 4, and the sweep of drill bit 30 will tend to not extend to the top of liner 4. That is illustrated in FIG. 3, which shows (in somewhat exaggerated scale for the sake of illustration) the sweep S_(B) of drill bit 30 relative to the inner circumference C_(L) of liner 4. It will be noted in FIG. 3 that sweep S_(B) leaves a crescent-shaped gap G within inner circumference C_(L) of liner 4. Because of gap G, drill bit 30 can leave relatively large or crescent-shaped debris as is mills through plug 20.

First Preferred Bit Adaptor

The novel drill bit adaptors may comprise a generally cylindrical body having a pair of offset axes, the first axis adapted to align substantially with the rotational axis of a drill-out tool assembly and the second axis being adapted to align substantially with the axis of a conventional drill bit. For example, as shown in FIG. 4, a first preferred embodiment 40 of the novel drill bit adaptors has a body 41 having a first or uphole end 42 and a second or downhole end 43. Uphole end 42 is adapted for assembly to a motor assembly or other work string (not shown) which will transmit rotational force to adaptor 40. For example, uphole end 42 is provided with a threaded pin. Downhole end 43 is adapted for assembly to a drill bit, such as drill bit 30. Thus, downhole end may be provided with, for example, a threaded box. A central passage 44 extends laterally through adaptor body 41 and is adapted to convey fluid through adaptor 40 and into passage 36 of drill bit 30.

Body 41 is substantially cylindrical, but it will be noted that it has a pair of slightly offset, major central axes A₁ and A₂. Axes A₁ and A₂ are referred to as major axes in that they run laterally, that is, along the length of adaptor 40 instead of across its width. Axis A₁ is central to uphole end 42 and portion of adaptor body 41. Axis A₂ is central to the downhole end 43 and portion of adaptor body 41.

When adaptor 40 is assembled to a drill-out tool assembly, axis A₁ is substantially aligned with, that is, it is substantially collinear with the rotational axis of the tool assembly (not shown). Axis A₁, therefore, provides an axis of rotation for adaptor 40. Axis A₁, however, is offset from axis A₁, that is, it is substantially non-collinear with axis A₁. As exemplified, axis A₂ is substantially parallel to, but spaced slightly away from axis A₁. It is substantially aligned with the rotational axis A_(B) of drill bit 30.

Thus, when the tool assembly is driving adaptor 40 and bit 30, adaptor 40 will extend the sweep of drill bit 30. For example, axes A₁ and A₂ in adaptor 40 are offset by 0.075″. Thus, the sweep of drill bit 30 will be extended from approximately 4.625″ to approximately 4.775″, essentially the inner circumference of liner 4. It is expected, therefore, that drill bit 30 will be able to more effectively remove plug 20 and minimize the creation of relatively large, crescent shaped debris.

It will be appreciated that in the example above, the degree to which parallel axes A₁ and A₂ are offset will depend primarily on the standard sweep of the drill bit and the inner diameter of the liner and the desired tolerances between those dimensions. Also, while axes A₁ and A₂ are offset, but generally parallel, they may be offset from each other angularly. The optimal angular offset, however, will vary according to the lateral dimensions of the adaptor and bit. Thus, it is generally preferred that the axes run generally parallel to each other.

Body 41 of bit 40 also is described as generally cylindrical. As depicted, it may be viewed generally as having the shape of two stacked, but somewhat offset cylinders bit 30 also is not in alignment with the rotational axis of adaptor 40. The weight of adaptor 40 and bit 30, therefore, is not distributed symmetrically about the axis A₁ of rotation. Thus, it may be desirable to provide the novel adaptors with a body that is somewhat eccentric or otherwise configured so as to distribute the mass of the adaptor in such a fashion as to offset somewhat the asymmetrical distribution of weight about the rotational axis. It may not be practical to do so exactly, given that the weight of conventional bits will vary, but improving the balance of the assembly will help minimize vibration and stress through the tools. Other approaches to balancing the weight of the novel adaptors and bit about the rotational axis of the adaptor, such as employing materials of differing densities, may be employed as well.

Other Preferred Bit Adaptors

At noted above, fluid preferably will be circulated through drill bit 30 to carry cuttings away from drill bit 30 and up to the surface during drill-out operations. Thus, the novel adaptors may have various features which can assist in circulating cuttings away from the bit and out of the well. For example, a second preferred embodiment 140 of the novel adaptors is shown in FIG. 5. Adaptor 140 is substantially identical to adaptor 40 except that it has one or more nozzles or ports, such as port 145. Port 145 extends laterally upward and radially outward from passage 44 through adaptor body 41 to the exterior of adaptor 40. Fluid will be directed out of adaptor 140 via port 145 and upward into the annulus between adaptor 140 and liner 4. Up-flow port 145, therefor, may assist in pushing cuttings up the annulus toward the surface.

A third preferred embodiment 240 is shown in FIG. 6, Adaptor 240 is substantially the same as adaptor 140, except that it has a down-flow port 245. That is, port 245 extends laterally downward and radially outward from passage 44. Port 245, therefore, directs fluid out of adaptor 240 and downward toward bit 30. Down-flow port 245, therefore, may assist in washing cuttings away from bit 30.

It will be appreciated that up-flow ports 145 and down-flow ports 245 may be varied in configuration and number to provide whatever flow characteristics may be deemed useful for a particular drill-out application. The design of suitable ports is well within the skill of workers in the art.

The novel adaptors also may incorporate features which assist in the breakup and removal of plug debris during drill-out. For example, a fourth preferred embodiment 340 of the novel adaptors is shown in FIGS. 7-9. Adaptor 340 is substantially identical to adaptor 40 except that it incorporates grinding or cutting members, such as inserts 346 arranged on a boss 347. Boss 347 extends radially outward from, and laterally along the exterior surface of the downhole portion 43 of adaptor body 41. Inserts 346 are carried in corresponding holes in boss 347 and may be made of the same hard materials as described above in reference to the cutting members on bit 30. Other cutting members, such as blades, may be mounted on boss 347 or otherwise on adaptor 340. Similarly, boss 347 may have grinding features, such as Cutrite and other metal binders incorporating carbide or other abrasive particles. A variety of cutting and grinding members may be provided on adaptor 340 in a variety of ways. Such features may assist in breaking up cuttings from a drill-out operation as they flow away from the drill bit past the adaptor.

Preferred Drill Bits

As noted above, the novel adaptors may be assembled to a conventional drill bit to provide the bit with a full sweep of the interior of a liner. Thus, it will be readily appreciated that the novel adaptors and conventional bits may be fabricated as an integral unit instead of as separate components. Thus, the subject invention also provides for drill bits which have a pair of offset axes. The first axis extends through and is central to an uphole portion of the bit. It is adapted to align substantially with the rotational axis of a drill-out tool assembly. The second axis extends through and is central to a downhole portion of the bit.

For example, a first preferred embodiment 130 of the novel drill bits is shown in FIG. 10. Drill bit 130 essentially incorporates drill bit 30 and novel adaptor 40 in an integral design. Thus, drill bit 130 is essentially a roller cone drill bit. It has a body 131, the downhole end of which is provided with three, rotatable cone assemblies 32. Cones 32 are provided with a several rows of hard, cutting inserts 35. Such downhole components of bit 130 and other features not mentioned here are substantially identical to the features of drill bit 30 described above.

Like drill bit 30, drill bit 130 is adapted for connection to a motor or other component of a drill-out tool assembly (not shown). Thus, the upper end of bit body 131 terminates in a threaded pin 133. Pin 133 allows bit 130 to be threaded, for example, into the drive shaft of a downhole motor. Bit body 131 also is provided with a central conduit 136 (shown in part) allowing fluids to be introduced into drill bit 130 through the tool assembly. Ports (not shown) extend from central conduit 136 through bit body 131, terminating in nozzles 37 which direct fluid out of bit 130 as it is rotated.

Like adaptor 40, drill bit 130 has a pair of slightly offset, major central axes B₁ and B₂. Axis B₁ is central to pin 133 and the uphole end of bit body 131. When drill bit 130 is assembled to a drill-out tool assembly, axis B₁ is substantially collinear with the rotational axis of the tool assembly (not shown). Axis B₁, therefore, provides an axis of rotation for drill bit 130. Axis B₂ is central to the downhole end of bit body 131 and cones 32 and other components carried thereon. Axis B 2 is parallel to, but spaced from axis B₁. Thus, when drill bit 130 is rotated by a tool assembly, the sweep of the downhole end of bit 130 will extend across the entire inner diameter of liner 4.

It will be appreciated that the novel adaptors and bits have been exemplified by reference to a particular design of roller cone bit. The novel adaptors, however, may be used with other roller cone bits, or they may be used with other types of drill bits, such as fixed head bits, or mill bits. A wide variety of conventional bits are known, and depending on the plug or other structure to be removed, may be used with the novel adaptors. Such bits include, for example, roller cone bits such as the SlipStream™ RC Pro bit available from Varel International Energy Services, Inc. (Dallas, Tex.), the ShredR™ bit available from National Oilwell Varco (Houston, Tex.), and the JZ HA-2G bit distributed by Barnett Bit, LLC (Wichita Falls, Tex.). Fixed head bits include the PlugBuster XLR bit available from Torquato Drilling Accessories (Old Forge, Pa.) and the FracDrill™ completion bit available from PDC Logic (Norman, Okla.). Concave or convex, standard clutch or reverse clutch mill bits also may be used. Thus, “drill” bits as used herein, unless the context clearly indicates otherwise, shall be understood as encompassing both drill bits in a narrow sense as well mill bits. Similarly, such conventional bits and others also may be modified generally as described above in reference to drill bit 130, to provide novel bits which have sweeps across the entire inner diameter of a liner.

Likewise, the novel bits and adaptors have been exemplified in the context of a particular frac plug which preferably is fabricated from more easily drillable materials such as composites. The novel bits and adaptors may be used, however, to drill out other conventional plugs. Similarly, operators may desire to drill out ball seats and other inner components of frac valves, other tools installed in a liner which have served their purpose or malfunctioned, or debris or other obstructions in the liner. The novel bits and adaptors may be adapted for use in such drill-out operations as well. Also, “liner” can have a fairly specific meaning within the industry, as do “casing” and “tubing.” In its narrow sense, a “liner” is generally considered to be a relatively large tubular conduit that does not extend from the surface of the well, and instead is supported within an existing casing or another liner. The novel adaptors and bits, however, may be used in drill-outs of casings and other tubular structures.

The bits and adaptors of the subject invention may be manufactured by methods and from materials commonly used in manufacturing drill and mill bits. Given the extreme stress and the corrosive and abrasive fluids to which the bits and adaptors are exposed, suitable materials will be hard and strong. For example, the adaptor and bit bodies may be manufactured from 4130 and 4140 chromoly steel or from somewhat harder, stronger steel such as 4130M7, high end nickel alloys, and stainless steel. Such components may be made by any number of conventional techniques, but typically and in large part will be made by forging, extruding, or mold casting a blank part and then machining the required features into the part. Seals and the like required, for example, in the bearing assemblies and grease system, will be fabricated from elastomers commonly used in downhole well tools. As noted above, the cutting members may be made from a variety of hard materials, and may be mounted or otherwise provided on the bit by welding, braising, fitting, and other well know techniques.

While this invention has been disclosed and discussed primarily in terms of specific embodiments thereof, it is not intended to be limited thereto. Other modifications and embodiments will be apparent to the worker in the art. 

1. (canceled)
 2. (cancelled)
 3. (canceled)
 4. An adaptor for a drill bit, said adaptor comprising: (a) a body having an uphole end and a downhole end; (b) said uphole end being adapted for releasable connection to a tool assembly for rotating a drill bit, said tool assembly having an axis of rotation; (c) said downhole end being adapted for releasable connection to a drill bit, said drill bit having an axis of rotation; (d) said body being adapted to transfer rotation of said tool assembly to said drill bit in both directions and having an uphole major axis and a downhole major axis, (e) said uphole axis being adapted for alignment with said tool assembly axis of rotation; (f) said downhole axis being adapted for alignment with said drill bit axis of rotation; (g) wherein said uphole axis and said downhole axis are offset from each other.
 5. The adaptor of claim 4, wherein said uphole axis and said downhole axis are substantially parallel to each other.
 6. The adaptor of claim 4, wherein said body defines a central passage extending laterally through said body.
 7. The adaptor of claim 5, wherein said body defines a central passage extending laterally through said body.
 8. The adaptor of claim 6, wherein said body defines a circulation port extending from said central passage to the exterior of said body, said port adapted to divert a portion of fluid from said central passage to the exterior of said adaptor above said drill bit.
 9. The adaptor of claim 7, wherein said body defines a circulation port extending from said central passage to the exterior of said body, said port adapted to divert a portion of fluid from said central passage to the exterior of said adaptor above said drill bit.
 10. The adaptor of claim 8, wherein said circulation port is directed downhole.
 11. The adaptor of claim 8, wherein said circulation port is directed uphole.
 12. A drilling tool assembly, said assembly comprising a drill bit and an adaptor of claim
 4. 13. A drilling tool assembly, said assembly comprising a drill bit and an adaptor of claim
 6. 14. A drilling tool assembly, said assembly comprising a chill bit and an adaptor of claim
 8. 15. The assembly of claim 10, wherein said drill bit is a rotary cone or fixed head drill bit.
 16. A method of performing an operation to drill out obstructions in a well tubular, said method comprising: (a) running a tool assembly into said tubular, said tool assembly having an axis of rotation and comprising a drill bit having one or more cutting members at its downhole end adapted for removing material from said obstruction, said downhole end of said tool bit having a central axis offset from said tool assembly axis of rotation; (b) rotating said tool assembly to cause said drill bit to drill out said obstruction.
 17. The method of claim 16, wherein said tool assembly comprises an adaptor having a first axis aligned with said tool assembly axis of rotation and a second axis aligned with said tool bit central axis.
 18. The method of claim 17, wherein said method comprises circulating fluid through a central passage extending laterally through said adaptor and a port extending from said central passage to the exterior of said adaptor above said tool bit.
 19. The method of claim 16, wherein said drill bit is a rotary cone or fixed head drill bit.
 20. The method of claim 17, wherein said drill bit is a rotary cone or fixed head drill bit. 